Hydrocarbons, such as oil and gas, may be recovered from various types of subsurface geological formations. The formations typically consist of a porous layer, such as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise through the nonporous layer. Thus, the porous layer forms a reservoir, that is, a volume in which hydrocarbons accumulate. A well is drilled through the earth until the hydrocarbon bearing formation is reached. Hydrocarbons then are able to flow from the porous formation into the well.
In what is perhaps the most basic form of rotary drilling methods, a drill bit is attached to a series of pipe sections or “joints” referred to as a drill string. The drill string is suspended from a derrick and rotated by a motor in the derrick. A drilling fluid or “mud” is pumped down the drill string, through the bit, and into the bore of the well. This fluid serves to lubricate the bit. The drilling mud also carries cuttings from the drilling process back to the surface as it travels up the wellbore. As the drilling progresses downward, the drill string is extended by adding more joints of pipe.
A modern oil well typically includes a number of tubes extending wholly or partially within other tubes. That is, a well is first drilled to a certain depth. Large diameter pipes, or casings, are placed in the well and cemented in place to prevent the sides of the borehole from caving in. The casing is cemented in the well by injecting a cement slurry down the casing, out the bottom of the casing, and up into the gap between the casing and the bore of the well, that is, the annulus. The cement then is allowed to harden into a continuous seal throughout the annulus.
After the initial section has been drilled, cased, and cemented, drilling will proceed with a somewhat smaller wellbore. The smaller bore is lined with somewhat smaller pipes or “liners.” The liner is suspended from the original or “host” casing by an anchor or “hanger.” A well may include a series of smaller liners, and May extend for many thousands of feet, commonly up to and over 25,000 feet.
Hydrocarbons, however, are not always able to flow easily from a formation to a well. Some subsurface formations, such as sandstone, are very porous. Hydrocarbons are able to flow easily from the formation into a well. Other formations, however, such as shale rock, limestone, and coal beds, are only minimally porous. The formation may contain large quantities of hydrocarbons, but production through a conventional well may not be commercially practical because hydrocarbons flow though the formation and collect in the well at very low rates. The industry, therefore, relies on various techniques for improving the well and stimulating production from formations. In particular, various techniques are available for increasing production from formations which are relatively nonporous.
Perhaps the most important stimulation technique is the combination of horizontal wellbores and hydraulic fracturing. A well will be drilled vertically until it approaches a formation. It then will be diverted, and drilled in a more or less horizontal direction, so that the borehole extends along the formation instead of passing through it. More of the formation is exposed to the borehole, and the average distance hydrocarbons must flow to reach the well is decreased. Fractures then are created in the formation which will allow hydrocarbons to flow more easily from the formation.
Fracturing a formation is accomplished by pumping fluid, most commonly water, into the well at high pressure and flow rates. Proppants, such as grains of sand, ceramic or other particulates, usually are added to the fluid along with gelling agents to create a slurry. The slurry is forced into the formation at rates faster than can be accepted by the existing pores, fractures, faults, vugs, caverns, or other spaces within the formation. Pressure builds rapidly to the point where the formation fails and begins to fracture. Continued pumping of fluid into the formation will tend to cause the initial fractures to widen and extend further away from the wellbore, creating flow paths to the well. The proppant serves to prevent fractures from closing when pumping is stopped.
A formation rarely will be fractured all at once. It typically will be fractured in many different locations or zones and in many different stages. Fluids will be pumped into the well to fracture the formation in a first zone. After the initial zone is fractured, pumping is stopped, and a plug is installed in the liner at a point above the fractured zone. Pumping is resumed, and fluids are pumped into the well to fracture the formation in a second zone located above the plug. That process is repeated for zones further up the formation until the formation has been completely fractured.
Fracturing typically involves installing a production liner in the portion of the wellbore passing through the hydrocarbon bearing formation. The production liner may incorporate valves, typically sliding sleeve “ball-drop” valves. The valve may be actuated by deploying a ball into the valve to open ports in the valve and to plug its bore. The ball restricts flow through the liner and diverts fluid through the ports and into the formation. Once fracturing is complete various operations will be performed to remove the balls and allow fluids from the formation to enter the liner and travel to the surface.
In many wells, however, the production liner does not incorporate valves. Instead, fracturing will be accomplished by “plugging and perfing” the liner. In a “plug and perf” job, the production liner is made up from standard joints of liner. The liner does not have any openings through its sidewalls, nor does it incorporate frac valves. It is installed in the wellbore, and holes then are punched in the liner walls. The perforations typically are created by so-called “perf” guns which discharge shaped charges through the liner and, if present, adjacent cement.
Regardless of whether it incorporates frac valves or will be perforated, a production liner typically will include a valve which is used to establish fractures in a first zone near the bottom of the well. Such “initiator” or “toe” valves are assembled into the liner. Though not necessarily the only design, one common type of toe valve has a hydraulically actuated sliding sleeve. The toe valve is run into the well with the sleeve in a closed position. In its closed position, the sleeve prevents fluid from flowing out of the liner through the valve ports. Hydraulic pressure may be applied to the sleeve to move it to an open position in which the ports are open and fluid is able to flow out of the liner into the formation.
As noted, a production liner typically will be cemented in the bore before fracturing is started. That generally entails pumping cement through the toe valve. Cement left behind in a toe valve, however, can harden and create various issues. It may hinder or preclude movement of the sleeve. Cement also can plug ports and other passages in the valve, interfering with operation of the valve or flow out of the valve. Cement wiper plugs typically are deployed behind the cement slurry to wipe inner surfaces clean. They are not always effective in removing cement, however, especially when the interior surfaces of the toe valve are highly profiled. Thus, there are various designs for so-called “smooth bore” toe valves.
On such design is disclosed in U.S. Pat. No. 9,476,282 to K. Anton et al. The toe valves disclosed therein include a pair of cylindrical primary structural components or “subs.” The subs are coupled together and spaced apart by a cylindrical housing. A sleeve is hydraulically mounted radially between the housing and the subs. An aperture is provided in one of the subs. The aperture allows fluid to flow into a hydraulic chamber above the sleeve. The aperture is normally closed by a pressure device, such as a rupture disc. As pressure increases within the bore, the disc will rupture and fluid will flow into the chamber. The fluid entering the chamber will drive the sleeve, moving it from its closed to its open position and allowing fluid to flow out of the valve.
It will be appreciated, however, that the aperture is exposed to cement fluid flowing through the valve during a cement job. Cement may harden in the aperture and block flow through the aperture or interfere with operation of the rupture disc. For example, if cement sets in or over the rupture disc, it may not burst at its rated pressure. Pressure in the liner may have to be raised, possibly beyond the liner's pressure rating, in order to rupture the disc and actuate the toe valve.
The statements in this section are intended to provide background information related to the invention disclosed and claimed herein. Such information may or may not constitute prior art. It will be appreciated from the foregoing, however, that there remains a need for new and improved systems, apparatus, and methods for initiating fracturing and other stimulation operations in an oil and gas well. Such disadvantages and others inherent in the prior art are addressed by various aspects and embodiments of the subject invention.